‘Petroleum’ means crude oil including heavy and residual oils in any reservoir, bitumen in tar sands, natural gas, gas condensate and any hydrocarbon containing fluid producible through boreholes or solid and fluid hydrocarbon containing materials recoverable from mining of tar sands or bitumen containing reservoirs of any type.
When oil is present in porous and permeable subterranean rock formations such as sandstone, carbonate, chert, shale or fractured rocks of any type, it can generally be exploited by drilling into the oil-bearing formation and allowing existing pressure gradients to force the oil through the reservoir and up into a borehole. This process is known as primary recovery.
If and when the pressure gradients are insufficient to produce oil at the desired rate, it is common to carry out an improved recovery method to recover additional oil. This process is known as secondary recovery.
There are several secondary recovery techniques, including gas injection and water injection. Choice of a specific secondary recovery technique depends on the specifics of the petroleum accumulation. Water injection or water flooding is the most common secondary recovery technique. In water flooding, pressurized water is injected into the petroleum-bearing formation and oil and/or gas is produced from neighbouring petroleum production wells. First petroleum, and subsequently petroleum and water are recovered from the production well.
However, even after secondary recovery, a significant portion of petroleum remains in the formation, usually in excess of 50% and in some cases over 75% of the original petroleum in place. The fraction of unrecoverable petroleum is typically highest for heavy oils, bitumens, and petroleum in complex reservoir formations. In many oil fields, a very large fraction of the oil (40% or much more) can be left after conventional waterflooding. Much of this remaining oil is trapped due to capillary forces or adsorption onto mineral surfaces and represents an irreducible oil saturation. Additional oil is trapped as bypassed oil within the reservoir rock formation missed by primary and secondary recovery techniques. This remaining residual oil may be recovered by enhanced recovery techniques. One enhanced oil recovery technique uses microorganisms (either indigenous or introduced artificially) to displace the trapped or adsorbed oil from the rock. The goal of this technique, which is known as microbially enhanced oil recovery (MEOR), is to increase recovery of the original subsurface petroleum. MEOR processes typically use microorganisms to: (1) alter the permeability of the subterranean formation by blocking reservoir porethroats to divert injected water flow to regions still saturated with oil, (2) produce biosurfactants which decrease petroleum/water interfacial tensions and mediate changes in wettability releasing oil, (3) produce polymers which facilitate increased mobility of petroleum in the reservoir, (4) produce low molecular weight acids which cause rock dissolution and increase permeability, and (6) generate gases (predominantly CO2) that increase formation pressure and reduce oil viscosity when dissolved in the oil.
Numerous microorganisms have been proposed for achieving various microbial objectives in subterranean formations. Most MEOR techniques involve injection and establishment of an exogenous microbial population in the oil-bearing formation. The population is supplied with growth substrate and mineral nutrients as additives to the waterflood used for secondary oil recovery. The growth of exogenous microorganisms is often limited by the conditions that prevail in the formation. Physical constraints, such as the small and variable formation pore throat diameters together with the high temperatures, salinities and pressures of fluids in the formation and the low concentrations of oxygen in the formation water severely limits the types of microorganisms that can be injected and that will thrive in the formation. Biological constraints, such as competition from indigenous reservoir microbes, the inherently adverse environment of subsurface reservoirs and the stress of changing environment from surface to reservoir also act to limit the viability of exogenously supplied microorganisms. To overcome these problems, indigenous reservoir microorganisms, commonly anaerobic organisms, have been proposed for use in MEOR techniques.
Microorganisms are commonly present in petroleum reservoirs cooler than about 80° C. (Bernhard and Connan, 1992; Magot et al., 2000; Orphan et al., 2000; Wilhelms et al., 2001). Biodegradation of petroleum, both crude oil and natural gas, in the subsurface is a common process (Connan, 1984; James, 1984; Horstad and Larter, 1997; Wenger et al., 2001; Head et al., 2003 and refs therein). With appropriate environmental conditions and sufficient time, indigenous bacteria and archaea can convert petroleum or other fossil fuels such as coals to methane over long geological time periods in the subsurface (Scott et al., 1994; Head et al., 2003; Roling et al., 2003 and refs therein). Methanogenesis, an exclusively anaerobic process, is commonly associated with biodegraded petroleum reservoirs. Methane containing isotopically lighter carbon is frequently found admixed with thermogenic methane (Scott et al., 1994; Larter et al., 1999; Sweeney and Taylor, 1999; Pallasser, 2000; Masterson et al., 2001; Boreham et al., 2001; Dessort et al., 2003) and methanogens represent common indigenous members of petroleum reservoir microflora (Mueller and Nielsen, 1996; Nilsen and Torsvik, 1996; Nazina et al., 1995 a,b; Ng et al., 1989). The methanogens described are those that reduce carbon dioxide to methane with few reports of acetoclastic methanogens from petroleum reservoirs (Obraztsova, 1987). Radiotracer experiments indicate that carbon dioxide reduction to methane is more prevalent than acetoclastic methanogenesis (Mueller and Nielsen, 1996; Rozanova et al., 1995) and high pressures in petroleum reservoirs favour net volume reducing reactions such as methanogenesis from carbon dioxide reduction (Head et al., 2003). The conversion process is slow under most geological conditions and it has been shown that typically it takes many millions of years to naturally biodegrade oil in a reservoir (Larter et al., 2003). In addition it has been shown, that degradation is often anaerobic in nature and that methane is often the natural end product of oil degradation (Larter et al., 1999; Head et al., 2003) with a significant proportion of the methane produced being associated with the reduction of carbon dioxide using secondary sources of hydrogen (Röling et al. 2003). Recent developments in microbiology have also demonstrated the existence of microbial consortia which can directly convert hydrocarbons to methane under conditions likely to be found in petroleum reservoirs (Zengler et al., 1999; Anderson and Lovely, 2000).
The first order kinetic rate constants of biodegradation of hydrocarbons and non-hydrocarbons in petroleum reservoirs under natural conditions has been shown to be around 10−6 to 10−7/year (Larter et al., 2003; Head et al., 2003), approximately 10,000 to 100,000 times slower than anaerobic hydrocarbon degradation rates in shallow subsurface environments such as landfills or shallow aquifers. To commercially recover significant quantities of oil as methane in realistic timescales of months to years using microbial technologies, the inventors have shown that degradation of large fractions of an oil layer must be accelerated to near-surface rates of methanogenesis. FIG. 1 shows a computer simulation of oil biodegradation throughout an entire 26 m oil column where methanogenesis is occurring at the rates typical in a near surface landfill environment. 20% of the remaining oil in the reservoir is recovered in approximately 10 years.
Thus to produce commercial quantities of methane by microbial degradation of petroleum in reservoirs under anaerobic conditions, technologies for acceleration of methane generation rates are needed and the degree of enhancement required to achieve commercial rates of production must be defined.
U.S. Pat. No. 6,543,535 outlines a process for stimulating microbial activity in petroleum-bearing subterranean reservoir formations, comprising:    (a) analyzing one or more components of the formation to determine characteristics of the formation environment;    (b) detecting the presence of a microbial consortium within the formation;    (c) characterization of one or more microorganisms of the consortium, at least one of the consortium members being at least one methanogenic microorganism, and comparing the members of the consortium with at least one known microorganism having one or more known physiological and ecological characteristics;    (d) using information obtained from steps (a) and (c) for determining an ecological environment that promotes in situ microbial degradation of petroleums and promotes microbial generation of methane by at least one methanogenic microorganism of the consortium; and    (e) modifying the formation environment based on the determinations of step (d) to stimulate microbial conversion of petroleums to methane.